Oil accumulated within a subterranean oil-bearing formation is recovered or produced therefrom through wells, called production wells, drilled into the subterranean formation. A large amount of such oil may be left in the subterranean formations if produced only by primary depletion, i.e., where only formation energy is used to recover the oil. Where the initial formation energy is inadequate or has become depleted, supplemental operations, often referred to as secondary, tertiary, enhanced or post-primary recovery operations, may be employed. In some of these operations, a fluid is injected into the formation by pumping it through one or more injection wells drilled into the formation, oil is displaced within and is moved through the formation, and is produced from one or more production wells drilled into the formation. In a particular recovery operation of this sort, seawater, field water or field brine may be employed as the injection fluid and the operation is referred to as a waterflood. The injection water may be referred to as flooding liquid or flooding water as distinguished from the in situ formation, or connate, water. Fluids injected later can be referred to as driving fluids. Although water is the most common, injection and drive fluids can include gaseous fluids such as air, steam, carbon dioxide, and the like.
A polymer additive may be added to an aqueous injection fluid to increase and/or adjust the viscosity of the injection fluid and aid in displacement of hydrocarbon compounds toward the production well. The viscosity of the injection fluid is usually selected with respect to the properties of the formation and the hydrocarbon compounds within the formation, e.g., the viscosity and/or density of the hydrocarbon compounds.
Ionically charged polymers are frequently used as viscosifying agents for such injection fluids. When using polymers containing an electrical charge, such as anionic polymers, the amount of polymer needed to achieve a given increase in viscosity decreases with a decrease in the total dissolved solids within the injection fluid. An injection fluid having a low total dissolved solids (“TDS”) content, e.g. from 500 ppm to 25000 ppm TDS, may be utilized to minimize the amount of polymer to reach a desired viscosity of the injection fluid, which minimizes the cost of preparing the injection fluid.
Hydrocarbon-bearing formations may adsorb polymer from an injection fluid containing an ionically charged polymer, delaying recovery of hydrocarbons, reducing the rate of such recovery, promoting fingering of the injection fluid through the formation resulting in early breakthrough of the injection fluid at a production well, and/or increasing costs of recovery due to polymer loss. As an ionically charged polymer injection fluid is introduced into and interacts with a formation, the charged polymer adsorbs onto the formation surface until the polymer adsorption potential of rock in contact with the polymer injection fluid is reached. As a result, propagation of the polymer injection fluid through the formation may be slowed by adsorption of the polymer on to the formation and lower viscosity polymer-depleted polymer fluid may finger through the hydrocarbons in the formation resulting in early breakthrough of the injection fluid at the production well.
Furthermore, when a polymer injection fluid having a low TDS content and low polymer concentration is utilized, the amount of polymer injection fluid required to satisfy the adsorption potential of the formation is large due to the relatively small amount of polymer present in the polymer injection fluid. As polymer is adsorbed from a polymer injection fluid having a low initial polymer concentration, the polymer injection fluid front will propagate more slowly through the formation as the viscosity of the polymer injection fluid drops due to loss of polymer. Slower propagation of the injection fluid results in either a delay in oil recovery or slower rate of oil recovery. Accordingly, the efficiency and cost benefits of using an injection fluid with a lower level of total dissolved solids and corresponding lower polymer concentration must typically be weighed against the resulting increase in oil recovery time, increased fingering of the injection fluid through the hydrocarbons in the formation, and the increase in volume of polymer injection fluid required to satisfy the formation polymer adsorption potential.